CN101892837A - Formation factor determining method and oil saturation determining method - Google Patents
Formation factor determining method and oil saturation determining method Download PDFInfo
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- 230000015572 biosynthetic process Effects 0.000 title claims abstract description 51
- 238000000034 method Methods 0.000 title claims abstract description 42
- 239000011435 rock Substances 0.000 claims abstract description 78
- 239000011148 porous material Substances 0.000 claims abstract description 42
- 230000035699 permeability Effects 0.000 claims abstract description 25
- 239000004020 conductor Substances 0.000 claims description 21
- 238000002474 experimental method Methods 0.000 claims description 20
- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 claims description 15
- 239000008398 formation water Substances 0.000 claims description 11
- 229920006395 saturated elastomer Polymers 0.000 claims description 8
- 238000000205 computational method Methods 0.000 claims description 5
- 238000011545 laboratory measurement Methods 0.000 claims description 5
- 238000004458 analytical method Methods 0.000 claims description 4
- 238000004457 water analysis Methods 0.000 claims description 3
- 238000011161 development Methods 0.000 abstract description 2
- 239000012530 fluid Substances 0.000 abstract 4
- 238000010586 diagram Methods 0.000 description 6
- 238000005553 drilling Methods 0.000 description 5
- 230000000694 effects Effects 0.000 description 5
- 238000007789 sealing Methods 0.000 description 5
- FAPWRFPIFSIZLT-UHFFFAOYSA-M Sodium chloride Chemical compound [Na+].[Cl-] FAPWRFPIFSIZLT-UHFFFAOYSA-M 0.000 description 4
- 238000012360 testing method Methods 0.000 description 3
- 238000005516 engineering process Methods 0.000 description 2
- 239000011780 sodium chloride Substances 0.000 description 2
- 238000006467 substitution reaction Methods 0.000 description 2
- 230000009286 beneficial effect Effects 0.000 description 1
- 238000010205 computational analysis Methods 0.000 description 1
- 230000002950 deficient Effects 0.000 description 1
- 238000011156 evaluation Methods 0.000 description 1
- 230000002349 favourable effect Effects 0.000 description 1
- 238000005259 measurement Methods 0.000 description 1
- 238000013508 migration Methods 0.000 description 1
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Abstract
The invention provides a formation factor determining method and an oil saturation determining method, wherein the formation factor determining method comprises the following steps: selecting a representative series of cores of a hyposmosis oil-gas layer with low secondary pore development, measuring and obtaining the porosity phi, the permeability K, a capillary pressure curve Pc and the average pore throat radius of the cores
(ii) a Where the porosity phi reflects the volume of conductive fluid in the rock,a reflective conductive path; the volume of the conductive fluid in the rock and the conductive path are taken as parameters for determining the formation factor F, and the specific relation is as follows:
determining a formation factor from the conductive fluid volume and the conductive path; wherein the coefficients a, b and c are obtained by calibrating core data. According to the invention, the volume of the conductive fluid and the conductive path are introduced as parameters for determining the formation factor, so that the calculation result of the formation factor is more consistent with the actual formation condition, and the result of determining the oil saturation is more accurate.
Description
Technical field
The present invention relates to the logging evaluation technology in the oil exploration, specifically is that a kind of low permeability reservoir formation factor determining method and the oil saturation based on conductor flow volume and conductive path that is applied in the well log interpretation determined method.
Background technology
The main task of well log interpretation is identification and quantitative assessment oil-gas Layer, with Archie formula and extend type thereof is that the electrical properties that representative is full of the water rock is the basis that utilizes well-log information quantitative assessment oil saturation, has brought into play important effect in the development of well logging quantitative interpretation.Classical Archie formula be applicable to have intergranular pore and hole, oozing property clean sandstone preferably, it has more single pore size distribution, the pore throat matching relationship is good, the ion migration be electric conduction of rock unique by way of.Classical Archie formula is:
Along with deepening continuously of oil exploration, it is found that Archie formula and various improved form thereof can not adapt to all reservoir types, particularly in the low-permeability oil deposit of secondary pore growing pore structure complexity, the influence factor complexity of rock electrical properties.For being full of the water rock, except that degree of porosity influenced the rock electrical properties, factors such as porosity type and content, pore structure often played control action to the influence of rock electrical properties.Low permeability reservoir for secondary pore growing, dissimilar hole proportion difference are very big, pore throat is bigger than changing, interpore connection situation varies, the reservoir hole relation of oozing is complicated, rock electrical properties and primary intergranular pore are that main sandstone has very big difference, show as Fei Aerqi rock electrical properties feature, the oil saturation of using the definite electrical properties calculating reservoir that is full of the water rock of classical Archie formula can produce very big error, influences the identification and the quantitative assessment of oil-gas Layer.
Summary of the invention
In view of problems of the prior art, the object of the present invention is to provide a kind of formation factor measurement and the method for determining and oil saturation to determine method, to solve inaccurate, the big defective of calculating oil saturation error that formation factor is determined in the prior art.
The embodiment of the invention provides a kind of formation factor determining method, comprises step: choose the representative serial rock core of secondary pore growing low osmoticing oil-gas layer, measure and obtain core porosity φ, permeability K, capillary pressure curve Pc, average pore throat radius
Wherein degree of porosity φ reflects conductor flow volume in the rock,
The reflection conductive path; As the parameter of determining formation factor F, the physical relationship formula is with conductor flow volume and conductive path in the rock:
According to conductor flow volume and conductive path, determine formation factor; Coefficient a, b wherein, c demarcate by core data and obtain.
The embodiment of the invention also provides a kind of oil saturation to determine method, comprises step: choose the representative serial rock core of secondary pore growing low osmoticing oil-gas layer, measure and obtain core porosity φ, permeability K, capillary pressure curve Pc, average pore throat radius
Wherein degree of porosity φ reflects conductor flow volume in the rock,
The reflection conductive path; As the parameter of determining formation factor F, the physical relationship formula is with conductor flow volume and conductive path in the rock:
According to conductor flow volume and conductive path, determine formation factor F; Coefficient a, b wherein, c demarcate by core data and obtain; Obtain formation water resistivity Rw by the water analysis data; Obtain reservoir resistivity Rt by well-log information; Use the A Erqi model and determine oil-bearing rock saturation exponent n, according to formula
Obtain the oil saturation of reservoir, wherein, S
OBe oil saturation; S
WBe water saturation.
Beneficial effect of the present invention is, by introducing conductor flow volume and conductive path as the parameter of determining formation factor, makes the more realistic strata condition of formation factor, and it is more accurate to measure the oil saturation result.
Description of drawings
Fig. 1 is the flow chart of formation factor determining method of the present invention;
Fig. 2 determines the flow chart of method for oil saturation of the present invention;
Fig. 3 is the formation factor determined by the present invention and the formation factor comparison diagram of experiment measuring;
Fig. 4 is the formation factor of A Erqi model calculating and the formation factor comparison diagram of experiment measuring;
Fig. 5 analyzes the oil saturation comparison diagram for stratum oil saturation and the sealing core drilling determined by the present invention.
The specific embodiment
The present invention is described in detail below in conjunction with accompanying drawing.
Embodiment one
Please refer to Fig. 1, Fig. 1 is the flow chart of formation factor determining method of the present invention, and as shown in Figure 1, formation factor determining method of the present invention comprises step:
Step 110: choose the representative serial rock core of secondary pore growing low osmoticing oil-gas layer, obtain core porosity φ, permeability K, capillary pressure curve Pc, average pore throat radius by measuring
Wherein degree of porosity φ reflects conductor flow volume in the rock,
The reflection conductive path;
(degree of porosity is between 5.3%～14.4%, and permeability is 0.1 * 10 to select 18 core samples in two layer positions of two blocks
-3μ m
2～26.0 * 10
-3μ m
2Between), experimentize according to " core analysis method (SY/T5336-2006) " and " mensuration of rock capillary pressure curve (SY/T5346-2005) " normal process, measure and calculate degree of porosity φ, the permeability K of every block of rock core, semi-permeable dividing plate capillary pressure curve Pc, average pore throat radius
Core porosity φ mentioned above is a decimal, and the unit of core permeability K is * 10
-3μ m
2, the unit of rock capillary pressure curve Pc is MPa, the average pore throat radius of rock core
Unit be μ m.
Step 120: as the parameter of determining formation factor F, the physical relationship formula is with conductor flow volume and conductive path in the rock:
According to conductor flow volume and conductive path, determine formation factor; Coefficient a, b wherein, c demarcate by core data and obtain.
The concrete steps that obtain described coefficient a, b, c comprise:
Choose the representative serial rock core of secondary pore growing low osmoticing oil-gas layer and carry out the rock physics experiment, measure and obtain core porosity φ, permeability K, capillary pressure curve Pc, average pore throat radius
Experiment measuring and calculate rock core saturated formation water resistivity R
WBe full of water rock resistivity R
0Using salinity is the NaCl solution saturated core of 20g/l, experimentizes according to " laboratory measurement of rock resistivity parameter and computational methods (SY/T5385-2007) " normal process, calculates formation water resistivity R at ambient temperature
W, measure and calculate every resistivity R that is full of the water rock core
0
Set undetermined coefficient a, b, c, order
Use the value that least square fitting obtains undetermined coefficient a, b, c.Coefficient a, b, c substitution following formula calculably the layer factor value.
For example: layer position one (rock core is numbered 1～7) match obtains a=0.68, b=0.22, c=25.7.
Layer position two (rock core is numbered 8～18) match obtains a=1.25, b=0.11, c=4.57.
Please refer to following table 1 again, itemized the contrast table that the rock physics experiment test obtains formation factor and uses the resulting formation factor of definite formation factor method of the present invention's proposition.
Table 1 rock physics experiment test and formula computing tables of data
The embodiment of the invention provides a kind of method of definite formation factor, by this method, can use degree of porosity φ, permeability K, average pore throat radius that conventional logging data and NMR logging data etc. obtain reservoir
Afterwards, can determine formation factor through computational analysis, simplified loaded down with trivial details laboratory operation flow process, and it has considered that conductor flow volume and conductive path are for the influence of formation factor in the rock, make the numerical value of formation factor can reflect real stratum characteristic more, the result is also more accurate.
Embodiment two
Please refer to Fig. 2 again, Fig. 2 is the flow chart that oil saturation of the present invention is determined method, and as shown in Figure 2, oil saturation of the present invention determines that method comprises step:
Step 210: choose the representative serial rock core of secondary pore growing low osmoticing oil-gas layer, obtain core porosity φ, permeability K, capillary pressure curve Pc, average pore throat radius by measuring
Wherein degree of porosity φ reflects conductor flow volume in the rock,
The reflection conductive path;
Step 220: as the parameter of determining formation factor F, the physical relationship formula is with conductor flow volume and conductive path in the rock:
According to conductor flow volume and conductive path, determine formation factor; Coefficient a, b wherein, c demarcate by core data and obtain.
The concrete steps that obtain described coefficient a, b, c comprise:
Choose the representative serial rock core of secondary pore growing low osmoticing oil-gas layer and carry out the rock physics experiment, measure and obtain core porosity φ, permeability K, capillary pressure curve Pc, average pore throat radius
Experiment measuring and calculate rock core saturated formation water resistivity R
WBe full of water rock resistivity R
0Using salinity is the NaCl solution saturated core of 20g/l, experimentizes according to " laboratory measurement of rock resistivity parameter and computational methods (SY/T5385-2007) " normal process, calculates formation water resistivity R at ambient temperature
W, measure and calculate every resistivity R that is full of the water rock core
0
Set undetermined coefficient a, b, c, order
Use the value that least square fitting obtains undetermined coefficient a, b, c.Coefficient a, b, c substitution following formula calculably the layer factor value.
Step 230: obtain formation water resistivity R by the water analysis data
WObtain reservoir resistivity R by well-log information
tUse the A Erqi model and determine oil-bearing rock saturation exponent n, according to formula
Obtain the oil saturation of reservoir, wherein, S
OBe oil saturation; S
WBe water saturation.
Use secondary pore growing low permeability reservoir formation factor value that formula of the present invention calculates and can reach and experimentize according to " laboratory measurement of rock resistivity parameter and computational methods (SY/T5385-2007) " normal process with the laboratory rock core and calculate the test effect of acquisition, the invention provides a kind of brand-new low permeability reservoir that is applicable to secondary pore growing and be full of water rock electrical model and definite flow process.
Formula of the present invention has the favorable actual application effect in the low permeability reservoir oil saturation quantitative assessment of secondary pore growing.Use the on-the-spot sealing core drilling analysis result of oil saturation and the oil field high conformity that model of the present invention calculates, improved the low permeability reservoir oil saturation computational accuracy of secondary pore growing.
Please refer to Fig. 3, Fig. 3 utilizes the formation factor of model calculating of the present invention and the formation factor comparison diagram that experiment measuring obtains, as can be seen from Figure 3, the two correlation of formation factor of utilizing formation factor that model of the present invention calculates and experiment measuring to obtain is good, data point distribution is near intersection Figure 45 ° line, the computational accuracy height, effect is obvious.
Please refer to Fig. 4 again, Fig. 4 utilizes the formation factor of A Erqi model calculating and the formation factor comparison diagram that experiment measuring obtains, as can be seen from Figure 4, low permeability reservoir for secondary pore growing, rock electrical properties and A Erqi model have bigger difference, show as Fei Aerqi rock electrical properties feature, the formation factor that formation factor that application A Erqi model calculates and experiment measuring obtain has very big error, and computational accuracy is starkly lower than model computational accuracy of the present invention.
Please refer to Fig. 5 again, Fig. 5 is that the stratum oil saturation and the sealing core drilling that utilize model of the present invention to calculate are analyzed the oil saturation comparison diagram.As can be seen from Figure 5, oil saturation that this model calculates and sealing core drilling are analyzed oil saturation high conformity, precision height.Analyze oil saturation with sealing core drilling and compare, it is 1.5% that oil saturation calculates mean absolute error, and oil field example proof model of the present invention has tangible practical application effect in the quantitative assessment of secondary pore growing low permeability reservoir oil saturation.
The foregoing description only is used to illustrate the present invention, but not is used to limit the present invention.
Claims (10)
1. a formation factor determining method is characterized in that, comprises step:
Choose the representative serial rock core of secondary pore growing low osmoticing oil-gas layer, measure and obtain core porosity φ, permeability K, capillary pressure curve Pc, average pore throat radius
Wherein degree of porosity φ reflects conductor flow volume in the rock,
The reflection conductive path;
As the parameter of determining formation factor F, the physical relationship formula is with conductor flow volume and conductive path in the rock:
According to conductor flow volume and conductive path, determine formation factor; Coefficient a, b wherein, c demarcate by core data and obtain.
2. method according to claim 1 is characterized in that, the concrete steps that obtain described coefficient a, b, c comprise:
Choose the representative serial rock core of secondary pore growing low osmoticing oil-gas layer and carry out the rock physics experiment, measure and obtain core porosity φ, permeability K, capillary pressure curve Pc, average pore throat radius
Experiment measuring and calculate rock core saturated formation water resistivity R
WBe full of water rock resistivity R
0Set undetermined coefficient a, b, c, order
Use the value that least square fitting obtains undetermined coefficient a, b, c.
3. method according to claim 2 is characterized in that, described rock physics experiment is to carry out according to " core analysis method (SY/T5336-2006) " and " mensuration of rock capillary pressure curve (SY/T5346-2005) " normal process.
4. according to claim 2 or 3 described methods, it is characterized in that described core porosity φ is a decimal, the unit of core permeability K is 10
-3μ m
2, the unit of rock capillary pressure curve Pc is MPa, average pore throat radius
Unit be μ m.
5. method according to claim 3 is characterized in that, described experiment measuring and calculate rock core saturated formation water resistivity R
WBe full of water rock resistivity R
0Be to carry out according to " laboratory measurement of rock resistivity parameter and computational methods (SY/T5385-2007) " normal process.
6. an oil saturation is determined method, it is characterized in that, comprises step:
Choose the representative serial rock core of secondary pore growing low osmoticing oil-gas layer, measure and obtain core porosity φ, permeability K, capillary pressure curve Pc, average pore throat radius
Wherein degree of porosity φ reflects conductor flow volume in the rock,
The reflection conductive path;
As the parameter of determining formation factor F, the physical relationship formula is with conductor flow volume and conductive path in the rock:
According to conductor flow volume and conductive path, determine formation factor F; Coefficient a, b wherein, c demarcate by core data and obtain;
Obtain formation water resistivity Rw by the water analysis data; Obtain reservoir resistivity Rt by well-log information; Use the A Erqi model and determine oil-bearing rock saturation exponent n, according to formula
Obtain the oil saturation of reservoir, wherein, S
OBe oil saturation; S
WBe water saturation.
7. method according to claim 6 is characterized in that, the concrete steps that obtain described coefficient a, b, c comprise:
Choose the representative serial rock core of secondary pore growing low osmoticing oil-gas layer and carry out the rock physics experiment, measure and obtain core porosity φ, permeability K, capillary pressure curve Pc, average pore throat radius
Experiment measuring and calculate rock core saturated formation water resistivity R
WBe full of water rock resistivity R
0
Set undetermined coefficient a, b, c, order
Use the value that least square fitting obtains undetermined coefficient a, b, c.
8. method according to claim 7 is characterized in that, described rock physics experiment is to carry out according to " core analysis method (SY/T5336-2006) " and " mensuration of rock capillary pressure curve (SY/T5346-2005) " normal process.
9. according to claim 7 or 8 described methods, it is characterized in that described core porosity φ is a decimal, the unit of core permeability K is
10
-3μ m
2, the unit of rock capillary pressure curve Pc is MPa, average pore throat radius
Unit be μ m.
10. method according to claim 7 is characterized in that, described experiment measuring and calculate rock core saturated formation water resistivity R
WBe full of water rock resistivity R
0Be to carry out according to " laboratory measurement of rock resistivity parameter and computational methods (SY/T5385-2007) " normal process.
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